Systems and methods for operating an islanded distribution substation using inverter power generation

ABSTRACT

Systems and methods are described herein to accommodate different settings associated with a converter-based electric power generator and an inverter-based electric power generator for electric power generation within an electric power delivery system. The electric power delivery system may provide electric power generated by a bulk electric system to the loads via distributed substations using a first operating frequency. Moreover, the distributed substations may include inverter-based electric power generators to supply the electric power demand of downstream loads in an islanded configuration. That said, the inverter-based electric power generators may supply the electric power using a second frequency that is higher than the first frequency. Protective systems, positioned downstream from the distributed substations, may use different settings associated with the bulk electric system or the inverter-based electric power generators based on detecting the frequency of the supplied electric power.

RELATED APPLICATION

This application claims the benefit under 35 U.S.C. § 119(e) of U.S.Provisional Application No. 63/239,691 filed Sep. 1, 2021, which ishereby incorporated by reference herein in its entirety.

BACKGROUND FIELD

The present disclosure relates generally to electric power deliverysystems and, more particularly, to monitoring and control systems thatprevent overloading of electric power sources.

Electric power delivery systems (e.g., macrogrids, distribution systems,among other things) are used to transmit electric power from generatorsto loads. The electric power delivery system may include aninverter-based electric power generation. Moreover, the electric powerdelivery system may include distributed substations and protectivesystems to facilitate transmission of electric power from generators toloads. Some electrical equipment may be able to receive electric powerfrom a bulk electric power system (BES) as well as local inverter-basedelectric power generators. Yet the electrical equipment may not run inexactly the same way regardless of whether the equipment is receivingpower from the BES or from the inverter-based power generators.

BRIEF DESCRIPTION OF THE DRAWINGS

Non-limiting and non-exhaustive embodiments of the disclosure aredescribed herein, including various embodiments of the disclosure withreference to the figures listed below.

FIG. 1 depicts an electric power delivery system including a bulkelectric system generation and inverter-based generation, in accordancewith an embodiment;

FIG. 2 depicts a method of operating the electric power delivery system,in accordance with an embodiment;

FIG. 3 depicts method of operating a point of common coupling breaker ofFIG. 1 based on whether the bulk electric system or the inverter isproviding the electric power to the loads, in accordance with anembodiment;

FIG. 4 depicts a graph of example operating frequencies of the inverterwhen the bulk electric system is primarily providing the electric powerto a substation of the electric power delivery system in relation tomethod of FIG. 3 , in accordance with an embodiment;

FIG. 5 depicts a graph of example operating frequencies of the inverterwhen the substation of the electric power delivery system is islanded inrelation to method of FIG. 3 , in accordance with an embodiment;

FIG. 6 depicts method of operating a fault current detector in theelectric power delivery system of FIG. 1 when the bulk electric systemis providing the electric power to the loads, in accordance with anembodiment;

FIG. 7 depicts method of operating a fault current detector in theelectric power delivery system of FIG. 1 when the inverter is providingthe electric power to the loads, in accordance with an embodiment; and

FIG. 8 depicts a graph of example frequency settings for operating oneor more fault current detectors of the electric power delivery system ofFIG. 1 in relation to methods of FIGS. 2 and 6 , in accordance with anembodiment.

DETAILED DESCRIPTION

When introducing elements of various embodiments of the presentdisclosure, the articles “a,” “an,” and “the” are intended to mean thatthere are one or more of the elements. The terms “including” and“having” are intended to be inclusive and mean that there may beadditional elements other than the listed elements. Additionally, itshould be understood that references to “some embodiments,”“embodiments,” “one embodiment,” or “an embodiment” of the presentdisclosure are not intended to be interpreted as excluding the existenceof additional embodiments that also incorporate the recited features.Furthermore, the phrase A “based on” B is intended to mean that A is atleast partially based on B. Moreover, the term “or” is intended to beinclusive (e.g., logical OR) and not exclusive (e.g., logical XOR). Inother words, the phrase A “or” B is intended to mean A, B, or both A andB.

Systems and methods are described herein to accommodate differentsettings associated with an inverter-based electric power generator forelectric power generation within an electric power delivery system. Anelectric power delivery system may include a number of distributedcomponents including an electric power source, a number of distributedsubstations, and a number of loads. The electric power delivery systemmay provide electric power generated by the electric power source to theloads via the distributed substations. Each distributed substation maybe coupled to the electric power source on one side and may be coupledto one or multiple loads on the other side of the distributedsubstation.

In some embodiments, the electric power source may include a bulkelectric power system (BES) for generating and providing electric powerto the loads. Moreover, one or more of the distributed substations,hereinafter substations, may also include a local electric power sourcesuch as one or multiple inverter-based electric power supplies(hereinafter inverters). For example, the inverters may producealternating current (AC) power from a direct current (DC) source (e.g.,battery). In some cases, the inverters may operate as battery-poweredelectric power sources.

A substation may provide electric power generated by the BES, theinverter, or both, to the loads coupled thereto. The substation mayprovide the electric power to the loads based on an electric powerdemand of the loads, the electric power generation of the BES, theelectric power generation of the inverter, or a combination of suchvariables, as will be appreciated. The substation may provide theelectric power to the loads via one or more feeders (e.g., feeder ordistribution lines).

The substation may include a transformer for providing the electricpower generated by the BES to the loads. For example, the transformermay adjust the electric power generated by the BES based on a standarddistribution voltage level. That said, different substations may providedifferent downstream distribution voltage levels to the respective loadsconnected thereto. In some embodiments, the substation may include aswitch or a point of common coupling (PCC) breaker between thetransformer and upstream transmission lines for connecting anddisconnecting the transformer from the BES.

When the PCC breaker is opened, the PCC breaker may disconnect the BESfrom the transformer. For example, the PCC breaker may open when the BESis overloaded, the BES is malfunctioning, or the BES is otherwiseproviding a fault current indicative of a fault condition of the BES. Insome embodiments, when the PCC breaker is opened, the substation mayprovide the electric power to downstream loads using the inverter (orthe inverters), as a dispatchable source. For example, the substationand the respective loads may operate as an isolated island or amicrogrid using the inverters.

When the PCC breaker is closed, the PCC breaker may connect the BES tothe transformer to provide the electric power to the downstream loads.However, the BES may become overloaded, may malfunction, or mayexperience unstable behavior. Moreover, in some cases, when the PCCbreaker is closed, the BES may provide zero, close to zero, or below athreshold electric power.

The substation may use the inverter (or inverters) to supplement the BESto supply the electric power demand (or a portion of the electric powerdemand) of the loads. For example, the substation or a controller of theelectric power delivery system may open the PCC breaker to indicate thatthe substation and the respective elements are islanded. As such, thesubstations may provide the electric power supplied by the inverter orthe BES to the loads, for example, by opening or closing the PCCbreaker.

With that in mind, the BES and the inverter may have different electricpower generation capabilities and/or characteristics. In some cases, acontroller may determine when the electric power source (e.g., theinverter or the BES) is overloaded. For example, when the inverter issupplying the electric power, the controller may determine whether theinverter is overloaded based on detecting a drop in the operatingfrequency higher than an inverter frequency drop threshold. Inalternative or additional embodiments, the controller may determinewhether the BES is overloaded based on detecting a drop in the operatingfrequency higher than a BES frequency drop threshold.

In any case, the controller may use different settings and/or thresholdsfor determining when the electric power source is overloaded. In someembodiments, overloading the inverter may result in a drop in thefrequency of the downstream electric current. However, in someembodiments, the BES may compensate for the droop in the frequency byshifting up the frequency curve using higher power. As such, the degreeof overloading the electric power source and the frequency droop may beproportional. Accordingly, the BES and the inverter may becomeoverloaded based on different frequency droop thresholds. For example,the BES and the inverter may use different operating frequencies andthreshold frequencies.

In such embodiments, the BES and the inverter may provide the downstreamelectric current using different operating frequencies (e.g., 60 Hertz(Hz) and 61 Hz, 50 Hz and 51 Hz). In some cases, a protective relayingscheme, disposed on the feeders, may determine the downstream operatingfrequency to detect whether the electric power delivery system issupplied by the inverter (e.g., islanded substation) or supplied by theBES. As such, the relaying scheme may use different frequency settingsfor load shedding based on whether the downstream electric power issourced from the BES or the inverter.

That said, the controller may use different thresholds for load sheddingand/or switching an operational state of the relaying scheme based onthe different frequency settings. In some embodiments, the relayingscheme may disconnect one or more loads from the substation (loadshedding) based on a BES power consumption threshold when the electricpower is sourced from the BES. In additional or alternative embodiments,the relaying scheme may shed one or more loads based on a frequencythreshold. Moreover, the relaying scheme may shed one or more loadsbased on a different frequency threshold when the electric power issourced from the inverter.

For example, some of the feeders of the electric power delivery systemmay include one or more fault current detectors disposed thereon. Afault current detector may include an intelligent electronic device(IED), a circuit breaker (or breaker), a relay, a capacitor bank, or acontroller. For example, an IED may receive and/or transmit a signaland/or data in order to perform a functionality, such as to control abreaker in response to electrical measurements of the electric powerdelivery system.

For instance, the electric power delivery system may use various faultcurrent detectors (e.g., IEDs) to control certain aspects of theelectric power delivery system. As used herein, an IED may refer to anyprocessing-based device that monitors, controls, automates, and/orprotects monitored equipment within the electric power delivery system.Although the present disclosure primarily discusses the IEDs as relaysand/or breakers, such as a remote terminal unit, a differential relay, adistance relay, a directional relay, a feeder relay, an overcurrentrelay, a voltage regulator control, a voltage relay, a breaker failurerelay, a generator relay, and/or a motor relay, additional IEDs mayinclude an automation controller, a bay controller, a meter, a reclosercontrol, a communications processor, a computing platform, aprogrammable logic controller (PLC), a programmable automationcontroller, an input and output module, and the like. Moreover, the termfault current detector and/or IED may be used to describe an individualIED or a system including multiple IEDs.

With the foregoing in mind, a fault current detector may detect a faultcurrent based on monitoring the operating frequency. For example, thefault current detector may determine a source of the electric powerbased on determining the operating frequency.

As mentioned above, in a non-limiting example, the BES may provide thedownstream electric power using 60 Hz nominal frequency and the invertermay provide the downstream electric power using 61 Hz nominal frequency.Accordingly, the fault current detector may correspond a downstreamelectric power with 60 Hz frequency to the BES and a downstream electricpower with 61 Hz frequency to the inverter, or islanded condition.

Moreover, based on determining the source of the electric power, thefault current detector may use the BES or the inverter frequencythresholds to determine whether the electric power source is overloaded.When satisfying a respective frequency threshold, the fault currentdetector may open one or more of the associated relays to shed one ormore loads, as will be appreciated.

With the foregoing in mind, FIG. 1 depicts an electric power deliverysystem 100 (e.g., an electric power distribution system, a macrogrid).The electric power delivery system 100 may be an example of the electricpower delivery system described above. The electric power deliverysystem 100 may include a BES 102 and an inverter 104 to supply electricpower to loads 106, 108, 110, 112, and 114. Moreover, the BES 102 andthe inverter 104 may provide a downstream electric current withdifferent operating frequencies (or nominal frequencies), as will beappreciated.

The BES 102 may electrically couple the loads 106, 108, 110, 112, and114 via a substation 116 (e.g., distributed substation). The BES 102 andthe substation 116 may electrically couple via a transmission line 118.The transmission line 118 may include a fault current detector 120. Afault current detector, such as the fault current detector 120 mayinclude a breaker (e.g., relay) and/or a controller. As described above,the fault current detector 120 may open or close the breaker based ondetecting a fault current (e.g., using the controller). For example, thefault current detector 120 may open the breaker to prevent damage to theBES 102, the substation 116, the loads 106, 108, 110, 112, and/or 114,among other components.

In some embodiments, the substation 116 may include the inverter 104, abreaker 122, a PCC breaker 124, a transformer 126, an electrical bus128, feeders 130 and 132, and fault current detectors 134 and 138. Thatsaid, in some cases, the substation 116 may communicatively couple theinverter 104, the PCC breaker 124, or other components positionedoutside the substation 116. The substation 116 may provide electricpower supplied by the BES 102, the inverter 104, or both to downstreamcomponents. The substation 116 may use the transformer 126 to adjust theelectric power supplied by the BES 102 and provide the adjusted electricpower to downstream components. For example, the transformer 126 mayadjust the electric power generated by the BES 102 based on a standarddistribution voltage level.

Moreover, in the depicted embodiment, the inverter 104 is coupled to ahigh side of the transformer 126. Accordingly, the substation 116 mayprovide electric power supplied by the inverter 104 to the downstreamcomponents via the transformer 126. For example, the substation 116 or acontroller associated with the electric power delivery system may openthe PCC breaker 124 and close the breaker 122 to allow the substation116 to provide the electric power. In alternative or additionalembodiments, the inverter 104 may be coupled to a low side of thetransformer 126. In such embodiments, the substation 116 may provideelectric power supplied by the inverter 104 to the downstream componentsby bypassing the transformer 126.

The PCC breaker 124 may electrically disconnect the substation 116 andthe BES 102 when opened. In some embodiments, a controller 144associated with the electric power delivery system 100 may open andclose a relay of the PCC breaker 124. Although the controller 144 isdepicted outside the PCC breaker 124, in alternative or additionalembodiments, the PCC breaker 124 may include the controller 144 or aportion of the controller 144. In some cases, the PCC breaker 124 mayopen when the BES 102 is overloaded or otherwise susceptible to failure.In some cases, when the PCC breaker 124 is open, the substation 116 mayuse the inverter 104 to supply at least a portion of the electric powerdemand associated with the loads 106, 108, 110, 112, and 114. Forexample, when the inverter 104 is providing the downstream electriccurrent, the controller of the PCC breaker 124 may open the relay of thePCC breaker 124 and instruct the inverter 104 to supply the electricpower based on a nominal operating frequency, as will be appreciated. Insuch cases, the substation 116 and the downstream components of theelectric power delivery system 100 may operate as an isolated island ormicrogrid.

With the foregoing in mind, in specific cases, when the PCC breaker 124is closed, the substation 116 may also use the inverter 104 to supply atleast a portion of the electric power demand. For example, thedownstream electric current supplied by the BES 102 may be lower than anelectric power threshold (e.g., a power flux threshold), may experiencea frequency lower than a threshold, or may experience other faultconditions. In such embodiments, the fault current detector 120, otherfault current detectors positioned downstream or upstream from thesubstation 116, or some other component of the electric power deliverysystem 100 may determine and communicate the fault conditions.Accordingly, the substation 116 may use the inverter 104 to supply allor a portion of the electric power demand associated with the loads 106,108, 110, 112, and 114.

The controller 144 may include one or more processors, microprocessors,programmable logic, or any combination of various elements forcontrolling operations of the substation 116. In some embodiments, thecontroller 144 may open and close the PCC breaker 124 and/or the breaker122. Accordingly, in such embodiments, the controller 144 may switch theelectric power source between the BES 102 and the inverter 104 forproviding the electric power to the loads 106, 108, 110, 112, and 114.In additional or alternative cases, one or more controllers positionedinside or outside the substation 116 may open and close the PCC breaker124 and/or the breaker 122, and/or switch the electric power sourcebetween the BES 102 and the inverter 104.

In any case, the substation 116 may provide the downstream electricpower via the electrical bus 128 to supply the electric power demand ofthe loads 106, 108, 110, 112, and 114. The electrical bus 128 may coupleto the feeders 130 and 132 to distribute the electric power in a radialelectric power delivery system. In the depicted embodiment, thesubstation 116 may provide the electric power to the loads 106 and 108via the feeder 130. Moreover, the substation 116 may provide theelectric power to the loads 110, 112, and 114 via the feeder 132.

The feeder 130 may include a fault current detector 134 and 136 and thefeeder 132 may include a fault current detectors 138, 140, and 142. Asmentioned above, the BES 102 and the inverter 104 may use differentoperating frequencies for providing the downstream electricpower/current. As such, the fault current detectors 134, 136, 138, 140,and 142 may monitor the operating frequency to detect the source of thesupplied electric power.

In some cases, the inverter 104 may include (or be associated with) acontroller. Such controller may adjust the frequency of the powergeneration based on a frequency and power droop curve, described belowwith respect to FIG. 5 . For example, the controller may be includedwith the controller 144, and IED, or any other viable device.

In any case, as mentioned above, a fault current detector, such as thefault current detectors 120, 134, 136, 138, 140, and 142 may include anIED, a breaker, a relay, a capacitor bank, and/or a controller. Forexample, the fault current detectors 120, 134, 136, 138, 140, and/or 142may receive and/or transmit a signal and/or data in order to perform afunctionality, such as to control the respective breaker in response toelectrical measurements of the electric power delivery system.

Moreover, the fault current detectors 134 and 138 may determineswitching between the electric power sources (e.g., the BES 102 and theinverter 104). For example, the fault current detectors 134, 136, 138,140, and/or 142 may determine (e.g., detect) whether the electric powersource is switched from the BES 102 to the inverter 104 when theoperating frequency becomes higher than a first frequency threshold.Moreover, the fault current detectors 134, 136, 138, 140, and/or 142 maydetermine whether the electric power source is switched from theinverter 104 to the BES 102 when the electric current frequency of thedownstream electric current becomes lower than a second frequencythreshold. In different embodiments, the first threshold and the secondthreshold may be similar or different.

Furthermore, as mentioned above, the BES 102 and the inverter 104 maybecome overloaded based on different electric power demand thresholds.Moreover, a frequency drop of the downstream electric current may becommensurate to a degree to which the electric power source isoverloaded. However, the BES 102 and the inverter 104 may be overloaded.Accordingly, based on determining the electric power source, the faultcurrent detectors 134, 136, 140, 142, and 138 may use a differentfrequency setting for load shedding.

In some embodiments, the fault current detectors 134, 136, 140, 142, and138 may include a breaker. Accordingly, when the BES 102 is providingthe electric power, the fault current detector 134 may open a respectivebreaker to shed the loads 106 and 108 when detecting a frequency lowerthan a frequency threshold. In some cases, the fault current detector136 may open a respective breaker to shed the loads 106 and 108 whendetecting a frequency lower than a frequency threshold. Moreover, thefault current detector 138 may open a respective breaker when detectinga frequency lower than a frequency threshold to shed the loads 110, 112,and 114. Furthermore, the fault current detectors 140 or 142 may openrespective breakers when detecting a frequency lower than a frequencythreshold to shed the loads 112 and 114 or 114 respectively.

With the foregoing in mind, the fault current detectors 142 and 140 maybe time-coordinated (e.g., synchronized) such that a breaker of thefault current detector 142 may open before the fault current detector140. For example, the breaker of the fault current detector 142 may openbased on a smaller frequency drop below a higher frequency threshold.That is, the fault current detector 140 may open based on a higherfrequency drop (e.g., higher degree of overloading the inverter 104) toshed the downstream loads. Accordingly, the fault current detector 142may shed the load 114 before the fault current detector 140 shedding theremaining load (e.g., the load 112).

Although specific arrangement of components is depicted in the electricpower delivery system 100 of FIG. 1 , in different embodiments, theelectric power delivery system 100 may use different arrangement ofcomponents. For example, in different or alternative embodiments, theelectric power delivery system 100 may include different number ofloads, fault current detectors, breakers, and electric power sources,arranged using similar or a different schematic. In differentembodiments, the fault current detectors 134, 136, 138, 140, and 142 maycontrol the respective breakers for granular load shedding based on oneor multiple frequency thresholds.

Moreover, it should be appreciated that in different embodiments, thefault current detectors may use different circuitry. For example, thefault current detectors 134, 136, 138, 140, and 142 may includedistributed sensors, controllers, or other circuitry disposed on thefeeders 130 and 132 respectively. With the foregoing in mind, FIGS. 2,6, and 7 describe methods 150, 200, and 300 for operating a faultcurrent detector in an electric power delivery system 100. For example,the methods 150, 200, and 300 may be associated with or used by thefault current detectors 134, 136, 138, 140, and 142 of the electricpower delivery system 100 described above. It should be appreciated thatthe methods 150, 200, and 300 may be performed by any viable computingsystem including any kind of viable storage circuitry, processingcircuitry, which may be included with, positioned in proximity of, orremotely from each of the fault current detectors of the electric powerdelivery system.

FIG. 2 depicts a method 150 associated with an example operation of theelectric power delivery system 100. For example, the method 150 may beperformed by a fault current detector (e.g., the fault current detectors134, 136, 138, 140, and/or 142) for determining frequency thresholds forload shedding and/or sensitivity of overcurrent thresholds. Additionallyand/or alternatively, the method 150 may be performed by a controllerassociated with the electric power delivery system 100, such as thecontroller 144 of the substation 116. The method 150 may cause loadshedding based on whether the electric power is supplied by the BES 102or the inverter 104 based on a connection state of the substation 116 tothe BES 102. For example, the controller 144 (or any other viablecontroller positioned inside or outside the inverter 104) may control anopen or closed state of the PCC breaker 124 and/or the breaker 122 toswitch to providing the downstream electric power provided by the BES102 or the inverter 104.

Referring now to block 152, the electric power delivery system 100 mayoperate to provide the electric power to the loads (e.g., the loads.106, 108, 110, 112, and 114). At block 154, the fault current detectormay determine whether the substation 116 connected to the BES 102. Basedon a connection state of the substation 116 to the BES 102, the faultcurrent detector may operate in a first mode or a second mode. In someembodiments, the fault current detector may determine whether thesubstation 116 is connected to the BES 102 based on detecting anoperating frequency of the electric power, as will be appreciated.

Additionally or alternatively, at block 154, the controller 144 maydetermine whether the substation 116 connected to the BES 102. Based onblock 154, the controller 144 may determine whether the fault currentdetectors 134, 136, 138, 140, and 142 may operate in a first mode or asecond mode. In some embodiments, the controller 144 may determinewhether the substation 116 is connected to the BES 102 based on a closedor open state of the PCC breaker 124 and/or the fault current detector120. In additional or alternative embodiment, the controller 144 maydetermine that the substation 116 is not connected to the BES 102 basedon detecting that the BES 102 is providing an unstable electric power, alower than an electric power threshold, or both.

At block 156, when the substation 116 is connected to the BES 102, thefault current detector and/or the controller 144 may use the traditionalfrequency thresholds (or BES frequency thresholds) for load shedding,for example, in the first mode. An example of the BES frequency droopthresholds may be provided below with respect to FIG. 5 . However, whenthe substation 116 is not connected to the BES 102, the fault currentdetector and/or the controller 144 may proceed to block 158.

At block 158, the opening of the PCC breaker shifts the operatingfrequency to a higher frequency (e.g., 61 or 51 Hz) than the BESoperating frequency (e.g., 60 or 50 Hz). Moreover, at block 158, thefault current detector may use more sensitive overcurrent thresholds andinverter-based frequency thresholds for load shedding and/or forprotecting the power system from faults in the second mode. Theovercurrent thresholds may refer to a current range for providing theelectric power to the downstream loads. For example, the fault currentdetectors may use higher sensitivity overcurrent thresholds. Moreover,the fault current detector may use the inverter frequency thresholdsthat are different from the traditional frequency thresholds for loadshedding, as will be appreciated.

FIG. 3 depicts a method 160 of determining a source of the downstreamelectric current at the PCC breaker 124 depicted in FIG. 1 . The PCCbreaker 124 may remain closed or may open based on whether the BES 102or the inverter 104 provide the downstream electric current. Forexample, the controller 144 may perform the process blocks of method 160to determine whether the BES 102 or the inverter 104 is providing thedownstream electric current. As mentioned above, the controller 144 maybe a standalone component of the substation 116 or may be associatedwith or included within the PCC breaker 124.

It should be appreciated that the described process blocks are by theway of example, and in different embodiments, different process blocksmay be used. Moreover, it should also be appreciated that in differentcases, some of the process blocks may be omitted or additional processblocks may be included. Moreover, FIGS. 4 and 5 depict example frequencyramp diagrams 180 and 190. The frequency ramp diagrams 180 and 190 aredescribed below with respect to some of the process blocks of the method160 of FIG. 3 , as will be appreciated.

At block 162, the controller 144 may measure a power flow through thePCC breaker 124. The controller 144 may measure a power flow through therelay of the PCC breaker 124. At block 164, the controller 144 maydetermine whether the measured power flow is below a threshold. Thethreshold may be associated with a power flow when the BES 102 isproviding a low electric power (e.g., the downstream electric current).For example, the threshold may be associated with a power flow when theBES 102 is idle, off, or otherwise providing a zero, close to zero, orlow electric power. Moreover, the threshold may be different indifferent embodiments.

At block 166, when the measured power flow is not below the threshold,the controller 144 may cause the PCC breaker 124 to remain closed (e.g.,connected). The controller 144 may cause the PCC breaker 124 to remainclosed based on determining that the BES 102 is providing the electricpower. That is, the controller 144 may determine that the BES 102 isproviding the electric power based on the measured power flow throughthe relay of the PCC breaker 124 being equal to or above the threshold.

At block 168, the controller 144 may instruct increasing the operatingfrequency of the inverter 104 when the measured power flow is below thethreshold. In some cases, increasing the operating frequency of theinverter 104 may increase the electric power flowing through the relayof the PCC breaker 124. For example, increasing the operating frequencyof the inverter 104 may cause an increase in the electric power measuredat the PCC breaker 124.

Moreover, in some embodiments, the controller 144 may instructincreasing the operating frequency of the inverter 104 based on a ramprate. In FIGS. 4 and 5 , an incremental frequency ramp 184 is depictedto illustrate increasing the operating frequency of the inverter 104based on a ramp rate. In the depicted embodiment, the incrementalfrequency ramp 184 may incrementally increase from an initial frequency182 of 60 Hz to an intermediary frequency 186 of 60.35 Hz.

However, it should be appreciated that the frequency values illustratedin FIGS. 4 and 5 are provided as an example and are not limiting.Accordingly, in other embodiments, the initial frequency 182 and theintermediary frequency 186 may include other frequency values. In anycase, increasing the operating frequency of the inverter 104 based onthe incremental frequency ramp 184 may reduce disturbance of thedownstream components such as the loads 106, 108, 110, 112, and 114 andthe fault current detectors 134, 136, 138, 140, and 142.

At block 170, the controller 144 may measure the power flow through thePCC breaker 124. For example, the controller 144 may measure the powerflow through the relay of the PCC breaker 124 when the operatingfrequency is increased to the intermediary frequency 186. In some cases,the intermediary frequency 186 may be predetermined or preset. At block172, the controller 144 may determine whether the measured power flow isbelow the threshold. That is, the controller 144 may determine whetherthe power flow through the relay of the PCC breaker 124 is above thethreshold based on increasing the operating frequency of the inverter104.

When the power flow is below the threshold, the controller 144 maydetermine that the BES 102 is the source of the electric power.Accordingly, at block 174, the controller 144 may instruct decreasingthe operating frequency of the inverter 104 when the measured power flowis below the threshold. For example, the controller 144 may instructdecreasing the operating frequency of the inverter 104 to the initialfrequency 182.

In some embodiments, the controller 144 may instruct decreasing theoperating frequency of the inverter 104 based on a frequency ramp 188.In FIG. 4 , the frequency ramp 188 is depicted to illustrate decreasingthe operating frequency of the inverter 104 based on a ramp rate.Moreover, decreasing the operating frequency of the inverter 104 basedon the frequency ramp 188 may reduce disturbance of the downstreamcomponents such as the loads 106, 108, 110, 112, and 114 and the faultcurrent detectors 134, 136, 138, 140, and 142.

Alternatively, when the power flow is equal to or above the threshold,at block 176, the controller 144 may instruct increasing the operatingfrequency of the inverter to an inverter nominal operating frequency. Asdescribed above, in some cases, the fault current detectors 134, 136,138, 140, and/or 142 of FIG. 1 may use inverter based frequencythresholds for load shedding based on the inverter nominal operatingfrequency. For example, the inverter nominal operating frequency may behigher than a high BES frequency threshold, as will be appreciated.

In FIG. 5 , an increased frequency 194 may illustrate transitioning fromthe intermediary frequency 186 to an inverter nominal operatingfrequency 192. In the depicted embodiment, the inverter nominaloperating frequency 192 is 61 Hz. However, in other embodiments, theinverter nominal operating frequency 192 may be different. For example,the downstream fault current detectors 134, 136, 138, 140, and/or 142 ofFIG. 1 may determine when the electric power is provided by the inverter104 based on detecting the inverter nominal operating frequency 192 thatis equal to or above a high BES frequency threshold.

Moreover, at block 178, the controller 144 may instruct the PCC breakerto open based on determining that the inverter is providing the electricpower. Accordingly, the substation 116, the downstream fault currentdetectors 134, 136, 138, 140, and 142, and the loads 106, 108, 110, 112,and 114 may become islanded based opening the PCC breaker 124.

Referring now to FIG. 6 , a method 200 of operating a fault currentdetector, such as the fault current detectors 134, 136, 138, 140, and/or142 of FIG. 1 is depicted. The method 200 starts at block 202 where aBES (e.g., the BES 102) is providing the electric power. In one example,the BES may provide the downstream electric current based on a 60 Hznominal operating frequency. At block 204, the fault current detectormay determine the operating frequency. As discussed above, the faultcurrent detector may be disposed on, attached to, or otherwiseelectrically connected to a feeder or distribution line to determine theoperating frequency. Moreover, in alternative embodiments, the faultcurrent detector may monitor the operating frequency continuously orbased on an interval time.

In any case, the fault current detector may compare the determinedoperating frequency with a high (e.g., maximum) BES frequency threshold(or traditional frequency threshold) at block 206 and with a BESfrequency droop threshold at block 208. In different embodiments, thefault current detector may perform the operations of the blocks 206 and208 consecutively, simultaneously, or in any suitable order. That is,although the blocks of the method 200 is depicted and described in aparticular order, it should be appreciated that in differentembodiments, the operations of the blocks may be performed in any viableorder.

Referring back to block 206, when the operating frequency is above thehigh BES frequency threshold, the fault current detector may proceed toblock 210. In one example, when the nominal frequency of the electricpower is 60 Hz, the high BES frequency threshold may be 60.3 Hz. In someembodiments, the BES may not operate at a higher frequency than the highBES frequency threshold. Accordingly, detecting a operating frequencyhigher than the high BES frequency threshold indicates a switch to adifferent electric power source (e.g., the inverter).

At block 210, the fault current detector may switch to using inverterfrequency droop thresholds for load shedding. In additional oralternative embodiments, the fault current detector may use other inputsand/or indications before switching to using the inverter frequencydroop thresholds for load shedding at block 210. Moreover, in somecases, subsequent to switching to use the inverter-generation frequencythresholds for load shedding at block 210, the fault current detectormay operate according to operations of the method 300 described belowwith respect to FIG. 4 .

Referring back to block 208, when the operating frequency is equal to orbelow a BES frequency droop threshold, the fault current detector shedsone or more loads (e.g., the loads 106, 108, 110, 112, and/or 114 ofFIG. 1 ) at block 214. In different embodiments, the fault currentdetector may shed different number of loads. Moreover, in specificembodiments, the fault current detector may use multiple BES frequencydroop thresholds to shed different number of loads. For example, thefault current detector may compare the operating frequency to themultiple BES frequency droop thresholds to shed a respective number ofloads.

In any case, when the operating frequency is above the BES frequencydroop threshold, the fault current detector may perform no actions atblock 216. That is, the fault current detector may not shed loads atblock 216. In one example embodiment, subsequent to operations of blocks214 and 216, the fault current detector may repeat the process of method200 by starting over at block 202.

Referring now to FIG. 7 , a method 300 for operating a fault currentdetector, such as the fault current detectors 134, 136, 138, 140, and/or142, is depicted. The method 300 starts at block 302 where an inverter(e.g., the inverter 104) is providing the electric power. In oneexample, the inverter may provide the downstream electric power based ona 61 Hz nominal frequency. That is, the inverter may use a differentnominal operating frequency for providing the downstream electric powerthat is higher than the operating frequency of the downstream electricpower provided by the BES. In some embodiment, the inverter may providethe downstream electric power using a higher nominal operating frequencythan the BES by more than a margin sufficient for implementing theinverter frequency droop thresholds.

In any case, at block 304, the fault current detector may determine theoperating frequency. The fault current detector may monitor theoperating frequency continuously or based on an interval time. At block306, the fault current detector may compare the determined operatingfrequency with a low (e.g., minimum) inverter frequency threshold.Moreover, at block 308 the fault current detector may compare thedetermined operating frequency with an inverter-generation frequencythreshold. That said, in different embodiments, the fault currentdetector may perform the operations of the blocks 306 and 308subsequently, simultaneously, or in any suitable order.

At block 306, when the operating frequency is below (or equal to) thelow inverter frequency threshold, the fault current detector may proceedto block 310. In one example, when the nominal operating frequency ofthe electric power is 61 Hz, the low inverter frequency threshold may be60.21 Hz. In some embodiments, the inverter may not operate at a lowerfrequency than the low inverter frequency threshold (e.g., minimuminverter frequency threshold). Accordingly, detecting an operatingfrequency lower than the low inverter frequency threshold indicates aswitch to a different electric power source (e.g., the BES).

At block 310, the fault current detector may switch to usingBES-generation frequency thresholds for load shedding. In someembodiments, subsequent to switching to use the BES-generation frequencythresholds for load shedding at block 310, the fault current detectormay operate according to operations of the method 200 described abovewith respect to FIG. 6 . However, at block 306, when the operatingfrequency is above the low inverter frequency threshold, the faultcurrent detector may continue using the inverter frequency droopthresholds for load shedding at block 312.

Referring back to block 308, when the operating frequency is equal to orbelow an inverter frequency droop threshold, the fault current detectorsheds one or more loads at block 314. In different embodiments, thefault current detector may shed different number of loads. Moreover, inspecific embodiments, the fault current detector may use multipleinverter frequency droop thresholds to shed different number of loads.For example, the fault current detector may compare the operatingfrequency to the multiple inverter-generation frequency thresholds toshed a respective number of loads.

In any case, when the operating frequency is above theinverter-generation frequency threshold, the fault current detector mayperform no actions at block 316. That is, the fault current detector maynot shed loads at block 316 when the operating frequency is above theinverter frequency threshold. In one example embodiment, subsequent tooperations of blocks 314 and 316, the fault current detector may repeatthe process of method 300 by starting over at block 302.

While frequency thresholds for shedding loads at block 208 and 308 areused here as examples, any suitable different sets of protectionoperations may be performed upon determining that the BES is connectedto or disconnected from the microgrid based on the operating frequencybeing below or above the high BES threshold (i.e., from blocks 206, 306,and/or 154). Conversely, a second set of protection operations, such asmore sensitive (e.g., more precise) overcurrent protection operations,may be performed upon determining that the BES is disconnectedindicating that the inverter and the battery energy storage system arepowering the loads.

That is, the fault current detector may perform a first set ofprotection operations associated with the relatively higher inertia ofthe BES when the PCC breaker (e.g., PCC breaker 124) connects themicrogrid to the BES in the first mode. Moreover, the fault currentdetector may perform a second set of protection operations associatedwith the relatively lower inertia associated with the inverter and thebattery energy storage system when the PCC breaker (e.g., PCC breaker124) disconnects the microgrid from the BES in the second mode. Forexample, upon determining that the microgrid is islanded, the faultcurrent detector may enable voltage controlled definite timeover-current elements to improve stability of the islanded microgrid andmay disable utility protective operations (e.g., 51 element operations).Conversely, upon determining that the PCC breaker is closed and themicrogrid is connected to the BES, the fault current detector maydisable voltage controlled definite time over-current elements andenable utility protective operations.

Referring now to FIG. 8 , a graph 400 depicts an example frequencysetting for operating one or more inverters (e.g., battery inverters)associated with the electric power delivery system 100. Moreover, afault current detector (e.g., the fault current detectors 134, 136, 138,140, and/or 142) may include or use a memory device, one or moreprocessing circuitry, logic circuitry, and/or any other viable circuitryfor including and using the depicted frequency settings. For example,the fault current detector may use non-transitory computer readablemedia to store the frequency settings of graph 400.

With that in mind, the graph 400 depicts an example relationship betweenoperating frequency and power droop when using an inverter (e.g., theinverter 104 of FIG. 1 ) to provide electric power to downstream loads.The operating frequency droop of the electric power corresponds to adrop in supplied power caused by overloading the inverter. As such, thegraph 400 depicts operating frequency droop of an inverter nominaloperating frequency (e.g., 60 Hz) and a shifted inverter nominaloperating frequency (e.g., 61 Hz) compared to electric power droop perpower unit (pu). As discussed above, in some embodiments, the electricpower delivery system 100 may use the shifted inverter nominal operatingfrequency when the BES 102 is no longer connected. That is, when the BES102 is no longer connected, the inverter 104 may provide the electricpower using the shifted inverter nominal operating frequency and thefault current detectors 134, 136, 138, 140, and 142 may use differentsettings for load shedding, as mentioned above and discussed below.

Referring now to the depicted embodiment, in some embodiments, theinverter may provide the electric power using an inverter nominaloperating frequency 402 of 60 Hz. In some cases, the inverter may shiftup the operating frequency to a shifted operating frequency 412 tocompensate for a power drop (e.g., half unit power drop) by increasingthe operating frequency. That said, the shifted operating frequency 412may use a lower operating frequency than a switching frequency threshold410 discussed below.

In alternative or additional embodiments, the inverter may provide theelectric power using shifted inverter nominal operating frequency 404 of61 Hz. In the depicted embodiment, a high (e.g., maximum) frequencydroop of 0.7% Hertz per power unit (Hz/pu) may govern an inverterfrequency droop threshold (inverter F_(th)) 406 and a shifted inverterfrequency droop threshold (shifted inverter F_(th)) 408. That said, inalternative or additional embodiments, other frequency droop thresholds(e.g., 0.6% or 0.8% Hertz per power unit (Hz/pu)) may be used. Asdiscussed above, a controller associated with the inverter (e.g., thecontroller 144 or the inverter controller described above) may shift thenominal operating frequency above a marginal threshold when switchingfrom a BES power supply to the inverter. In the depicted embodiment, themarginal threshold may be shown by the switching frequency threshold410, as will be appreciated.

When the inverter is providing the electric power using the inverternominal operating frequency 402, the fault current detectors may openone or more breakers (e.g., load shedding) when the operating frequencyapproaches the inverter F_(th) 406. Moreover, when the inverter isproviding the electric power using the shifted inverter nominaloperating frequency 404, the fault current detectors may open one ormore breakers (e.g., load shedding) when the operating frequencyapproaches the shifted inverter F_(th) 408. In some cases, the invertermay provide the electric power using the shifted inverter nominaloperating frequency 404 when the electric power delivery system includesa BES providing the electric power using the inverter nominal operatingfrequency 402.

For example, when the BES is providing the electric power using theinverter nominal operating frequency 402, the fault current detectorsmay shed loads according to a first mode. Moreover, when the inverter isproviding the electric power using the shifted inverter nominaloperating frequency 404, the fault current detectors may shed loadsaccording to a second mode. Accordingly, the fault current detectors mayoperate according to different frequency settings when determining aswitched operational state based on the switching frequency threshold(e.g., the inverter F_(th) 406 and the shifted inverter F_(th) 408 inthe different modes).

For example, a fault current detector, at block 308 of the method 300,may determine whether the operating frequency is equal to or below theinverter F_(th) 406 or the shifted inverter F_(th) 408. The faultcurrent detector may operate in a first operational mode or a secondoperational mode based on the nominal operating frequency of thedownstream power. For example, the fault current detector may comparethe inverter nominal operating frequency with the switching frequencythreshold 410 to determine using the inverter F_(th) 406 or the shiftedinverter F_(th) 408 for load shedding.

In the depicted embodiment, the shifted inverter F_(th) 408 may equal afrequency droop threshold number within a range of 60 Hz and 61 Hz. Inone example, the inverter F_(th) 406 may equal 60.58 Hz. As such, afault current detector, at block 208 of the method 200, may determinewhether the operating frequency is equal to or below the shiftedinverter F_(th) 408 (e.g., 60.58 Hz). However, it should be appreciatedthat in different embodiments, other range of frequencies may be usedfor the inverter F_(th) 406 and the shifted inverter F_(th) 408. Forexample, the inverter F_(th) 406 and the shifted inverter F_(th) 408 mayeach be a percentage (e.g., 0.7%) lower than an operating frequency ofthe BES 102 and the inverter 104, respectively.

As mentioned above, the inverter may provide the downstream electricpower using the shifted inverter nominal operating frequency 404 that isusing a higher frequency than the BES operating frequency by more than amarginal threshold. For example, the BES operating frequency may beequal to or close to the inverter nominal operating frequency 402. Assuch, the fault current detectors may determine the electric powersource by determining the nominal operating frequency of the downstreampower. Accordingly, based on the electric power source, the faultcurrent detectors may use different measurement techniques, such asusing higher precision measurements for load shedding with inverterpower supplies, to coordinate load shedding and peak shavingfunctionality of the electric power delivery system 100.

In some embodiments, the switching frequency threshold 410 may be withina range of 60 Hz and 61 Hz (e.g., 60.3 Hz). Moreover, in someembodiments, the switching frequency threshold 410 may comprise a highswitching frequency threshold for switching to the inverter and a lowfrequency threshold for switching to the BES. That is, the fault currentdetector may determine a switch of the electric power source from theBES to the inverter when the operating frequency of the electric poweris higher than a high operating frequency threshold associated with theBES (e.g., 60.3 Hz). Moreover, the fault current detector may determinea switch of the electric power source from the inverter to the BES whenthe operating frequency is lower than a low current frequency thresholdassociated with the inverter (e.g., 60.23 Hz).

In any case, the switching frequency threshold 410 may be selected basedon a margin distance from the shifted inverter F_(th) 408 and theinverter nominal operating frequency 402. Nevertheless, the graph 400depicts one example of thresholds to be used with the electric powerdelivery system 100 including the BES 102 and the inverter 104 toprovide the electric power. Moreover, it should be appreciated thatother threshold may be used in different embodiments to providesufficient margins between the depicted thresholds.

The specific embodiments described above have been shown by way ofexample, and it should be understood that these embodiments may besusceptible to various modifications and alternative forms. It should befurther understood that the claims are not intended to be limited to theparticular forms disclosed, but rather to cover all modifications,equivalents, and alternatives falling within the spirit and scope ofthis disclosure. Moreover, the techniques presented and claimed hereinare referenced and applied to material objects and concrete examples ofa practical nature that demonstrably improve the present technical fieldand, as such, are not abstract, intangible or purely theoretical.Further, if any claims appended to the end of this specification containone or more elements designated as “means for [perform]ing [a function]. . . ” or “step for [perform]ing [a function] . . . ”, it is intendedthat such elements are to be interpreted under 35 U.S.C. 112(f).However, for any claims containing elements designated in any othermanner, it is intended that such elements are not to be interpretedunder 35 U.S.C. 112(f).

What is claimed is:
 1. A method, comprising: measuring, by a controller,a first power flow associated with a point of common coupling breaker;determining, by the controller, that the first power flow is below athreshold; providing, by the controller, instructions to increase anoperating frequency of an inverter higher than an initial operatingfrequency in response to determining that the first power flow is belowthe threshold; measuring, by the controller, a second power flowassociated with the point of common coupling breaker; determining, bythe controller, that the second power flow is equal to or above thethreshold based at least in part on increasing the operating frequencyof the inverter; and providing, by the controller, instructions to openthe point of common coupling breaker in response to determining that thesecond power flow is equal to or above the threshold based at least inpart on increasing the operating frequency of the inverter.
 2. Themethod of claim 1, comprising increasing, by the inverter, the operatingfrequency of the inverter based on an incremental ramp rate when thecontroller determines that the first power flow is below the thresholdand in response to receiving the instructions to increase the operatingfrequency.
 3. The method of claim 1, comprising providing, by thecontroller, instructions to increase the operating frequency of theinverter to an inverter nominal operating frequency in response todetermining that the second power flow is equal to or above thethreshold.
 4. The method of claim 1, comprising providing, by thecontroller, instructions to decrease the operating frequency of theinverter in response to determining that the first power flow is equalto or above the threshold.
 5. The method of claim 4, comprisingdecreasing, by the inverter, the operating frequency of the inverterbased on a ramp rate in response to receiving the instructions todecrease the operating frequency.
 6. The method of claim 1, whereinmeasuring the second power flow associated with the point of commoncoupling breaker is in response to determining that the operatingfrequency is increased to an intermediary frequency higher than theinitial operating frequency.
 7. The method of claim 1, wherein thecontroller, the point of common coupling breaker, and the inverter areassociated with a substation.
 8. The method of claim 1, wherein thepoint of common coupling breaker and the inverter are associated with asubstation, and wherein the controller is associated with a faultcurrent detector positioned downstream from the substation.
 9. A faultcurrent detector configured to: measure a first power flow associatedwith a point of common coupling breaker; determine that the first powerflow is below a threshold; provide instructions to increase an operatingfrequency of an inverter higher than an initial operating frequency inresponse to determining that the first power flow is below thethreshold; measure a second power flow associated with the point ofcommon coupling breaker; determine that the second power flow is equalto or above the threshold based at least in part on increasing theoperating frequency of the inverter; and provide instructions to openthe point of common coupling breaker in response to determining that thesecond power flow is equal to or above the threshold based at least inpart on increasing the operating frequency of the inverter.
 10. Thefault current detector of claim 9, wherein the fault current detector isconfigured to provide instructions to increase the operating frequencyof the inverter to an inverter nominal operating frequency in responseto determining that the second power flow is equal to or above thethreshold.
 11. The fault current detector of claim 9, wherein the faultcurrent detector is configured provide instructions to decrease theoperating frequency of the inverter in response to determining that thefirst power flow is equal to or above the threshold.
 12. The faultcurrent detector of claim 9, wherein measuring the second power flowassociated with the point of common coupling breaker is in response todetermining that the operating frequency is increased to an intermediaryfrequency higher than the initial operating frequency.
 13. Anon-transitory computer-readable medium comprising instructions, whereinthe instructions, when executed by processing circuitry, are configuredto cause the processing circuitry to perform operations comprising:measuring, by a controller, a first power flow associated with a pointof common coupling breaker; determining, by the controller, that thefirst power flow is below a threshold; providing, by the controller,instructions to increase an operating frequency of an inverter higherthan an initial operating frequency in response to determining that thefirst power flow is below the threshold; measuring, by the controller, asecond power flow associated with the point of common coupling breaker;determining, by the controller, that the second power flow is equal toor above the threshold based at least in part on increasing theoperating frequency of the inverter; and providing, by the controller,instructions to open the point of common coupling breaker in response todetermining that the second power flow is equal to or above thethreshold based at least in part on increasing the operating frequencyof the inverter.
 14. The non-transitory computer-readable medium ofclaim 13, wherein opening the point of common coupling sheds anelectrical load.
 15. The non-transitory computer-readable medium ofclaim 13, wherein the operations further comprise: increasing, by theinverter, the operating frequency of the inverter based on anincremental ramp rate when the controller determines that the firstpower flow is below the threshold and in response to receiving theinstructions to increase the operating frequency.
 16. The non-transitorycomputer-readable medium of claim 13, wherein the operations furthercomprise: providing instructions to increase the operating frequency ofthe inverter to an inverter nominal operating frequency in response todetermining that the second power flow is equal to or above thethreshold.
 17. The non-transitory computer-readable medium of claim 13,wherein the operations further comprise: providing instructions todecrease the operating frequency of the inverter in response todetermining that the first power flow is equal to or above thethreshold.
 18. The non-transitory computer-readable medium of claim 13,wherein measuring the second power flow associated with the point ofcommon coupling breaker is in response to determining that the operatingfrequency is increased to an intermediary frequency higher than theinitial operating frequency.